Competitive Power Ventures’ proposal to revamp ISO-NE‘s financial assurance rules failed to win approval from NEPOOL’s Participants Committee on Thursday, spelling the end of an effort that struggled to get off the ground in the stakeholder process.
CPV’s plan to change the financial assurance (FA) rules for the region’s Forward Capacity Market was designed to penalize projects that fall well behind their construction schedules. (See NE Stakeholders Propose Retirement, Financial Assurance Changes). It would add increments of FA at certain milestones in the construction process as well as create new FA categories.
After several rounds of stakeholder meetings in recent months, including a failed vote at the Markets Committee in April, the proposal picked up support from the renewables group RENEW after adopting several of the group’s recommendations. RENEW said the latest iteration “strikes a good balance between creating incentives to encourage market entry only when projects are sufficiently confident of success while not creating a barrier to entry for any size or type of new resource.”
But at the last hurdle, Thursday’s PC meeting, the proposal again fell short with 64.74% voting in favor when the motion needed 66.67% to pass.
The issue is not likely to go away after the Killingly Energy Center’s disruption of Forward Capacity Auction 16 spotlighted the question of financial assurance and project timelines.
Board Vote
In an executive session, the committee also voted on two nominees for the ISO-NE board.
One candidate was current board Chair Cheryl LaFleur, who is up for re-election, and the other is a new board member whose identity is being kept confidential until it is announced by ISO-NE. (See NEPOOL Participants Committee Briefs: April 7, 2022).
The grid operator’s board will vote next to approve the candidates.
Load Records
ISO-NE COO Vamsi Chadalavada informed the committee of several recent landmarks related to low minimum load caused by high solar penetration.
The grid operator set a new record low of 7,580 MW of minimum load on May 1, a low-demand Sunday featuring sunny skies and mild temperatures.
“New England’s power system is changing right in front of our eyes,” Chadalavada said in a press release on Thursday. “While these changes haven’t happened overnight, a day like May 1 is a good reminder of the progress New England has made in its transition to the future grid.”
OP and PP Changes
The PC also voted to approve changes to two operating procedures and one planning procedure that had previously been approved by the Reliability Committee, including:
revisions to OP-14 (addition of a reference to NX-12 and an exemption for DNE Dispatchable Generators and Continuous Storage Facilities);
revisions to OP-18 (edits resulting from biennial review — formatting and grammatical changes, updated references and terminology, and documentation of existing metering requirements for Alternative Technology Regulating Resources); and
revisions to PP5-6 (revisions clarifying treatment of facility re-dispatch under certain specific circumstances within the interconnection study and voltage response when interconnecting Distributed Energy Resources).
Kentucky regulators on Wednesday approved Liberty Utilities’ $2.8 billion acquisition of American Electric Power’s Kentucky operations while including multiple customer protections.
As part of the deal, Liberty will assume $1.221 billion in debt for AEP subsidiaries Kentucky Power Co. and Kentucky Transmission Co. (2021-00481). Liberty is a subsidiary of Algonquin Power and Utilities.
AEP will net $1.4 billion in cash after taxes and transaction fees, which it said it will use to invest in renewable energy in other company subsidiaries outside of Kentucky. Liberty’s purchase price includes a $585 million acquisition premium above Kentucky Power’s net book value.
AEP in early 2021 announced it was mulling a potential sale of its Kentucky operations.
Liberty said it will retain all 360 Kentucky Power and Kentucky-based AEP employees and will not seek to recover the transaction premium or one-time transition costs in customer rates.
The Kentucky Public Service Commission included several stipulations to make the deal support the public interest.
Among them, the PSC ordered that Kentucky Power’s ratepayers receive an initial $30 million to offset the “continued subsidization of transmission investments of other AEP affiliates.” After the deal closes, Kentucky Power will continue to be a member of the AEP East Transmission Zone in PJM as a non-affiliated participant. As such, Kentucky Power will continue to pay zonal transmission rates based on a collective transmission investment of AEP operating companies, instead of individual company costs. The PSC estimates that if Kentucky Power doesn’t withdraw from the AEP PJM transmission zone, its ratepayers will pay “at least” an additional $15 million annually over the next five years.
The PSC said the customer subsidy fund will continue post-transaction and warned the utilities that it would add another $45 million if Kentucky Power, AEP and Liberty don’t fix the pricing issue.
“AEP, Kentucky Power and Liberty are incentivized to fix this subsidization issue with active and immediate advocacy at the federal level,” the state commission said.
The parties to the deal also struck a bridge power coordination agreement that will allow AEP to “monitor, operate, and dispatch Kentucky Power’s transmission system for up to 24 months” if necessary to navigate the transition. Kentucky Power must remain a PJM transmission owner and load serving entity in AEP’s zone through 2024, when it satisfies AEP’s preexisting fixed resource requirement plan.
After that, Liberty said it will evaluate the benefits and costs of Kentucky Power’s participation in PJM. Liberty must get the commission’s permission should it choose to exit PJM.
The PSC also ordered creation of a $43.5 million fund to make up for AEP’s overdue restoration of its Kentucky distribution system from past storm damage. The regulators offered strong words regarding the past upkeep of AEP’s distribution lines.
“While these expenses are a result of storm damage, they are a direct result of Kentucky Power’s underinvestment in its system, including the failure to address appropriate loading levels required for the utility’s distribution system,” the commissioners wrote. “The commission noted the purpose of the fund is to ensure ratepayers are not harmed post-transaction by AEP’s under-investment over the years, and the company’s repeated failure to comply with the commission’s directives and suggestions to improve the distribution system.”
The fund can be used to reduce rates in Kentucky Power’s next rate case, the PSC said.
The commission’s order also greenlighted Liberty’s proposed $40 million fuel adjustment clause (FAC) credit for customers and a three-year deferral of the existing decommissioning rider for the 295 MW Big Sandy plant, a gas-fired facility on the Big Sandy River that was converted from coal in 2016.
The FAC credit will return the $40 million over 18 months between July 1 and Dec. 31, 2023, split 75% to residential customers and 25% to non-residential customers. The PSC said the FAC credit will provide “more transparency and predictability for customers.” If Liberty uses the PSC’s suggested allocation, a typical residential customer can expect bill credits of almost $33 during the winter months and $1.40 in all other months.
The PSC said that, while the three-year deferral of Big Sandy’s coal decommissioning rider will cause a longer recovery period and more costs to customers in the long run, it’s necessary for Kentucky Power to take the delay in order to securitize the rider.
OGE Energy (NYSE:OGE) on Thursday announced first-quarter earnings that were more than quintuple those of last year’s first quarter, which was marred by the severe winter storm.
The Oklahoma City-based company reported earnings of $279.5 million ($1.39/diluted share), compared to $52.7 million ($0.26/diluted share) for the same quarter a year ago. The increase was driven by higher operating revenues at OGE’s Oklahoma Gas & Electric subsidiary, partially offset by increased depreciation on a growing asset base and higher operations and maintenance expenses.
“Solid execution and load growth in the first quarter have us on plan for the year,” CEO Sean Trauschke said in a statement.
OGE’s load growth came in at 1.3% in the quarter, helped by a 2.7% unemployment rate in Oklahoma.
The company is continuing its exit from its joint partnership with CenterPoint Energy in Enable Midstream Partners, which they sold to Energy Transfer Partners late last year. (See OGE, CenterPoint Complete Enable’s Disposal.)
OGE has sold 21.75 million units of Enable through April and received $246 million in net pre-tax proceeds this year, which it plans to use in retiring short-term debt. Trauschke said the company expects to exit the majority of its position in Enable by the end of the year.
The company’s share price lost 34 cents during the day’s sell-off on Wall Street, closing at $39.34.
The Connecticut Senate on Tuesday passed a bill, 30-5, that would direct two state utilities to develop energy storage pilot programs in support of a 1-GW storage goal for 2030.
The bill (HB 5327) now goes to Gov. Ned Lamont for his signature, having passed the House of Representatives unanimously in mid-April.
As passed with amendments, HB 5327 would require Avangrid (NYSE:AGR) and Eversource Energy (NYSE:ES) to submit three proposals each by the end of the year to the Public Utilities Regulatory Authority for pilot programs to build, own and operate energy storage systems. The bill would also limit the utilities’ current authority to own energy storage by requiring that any new facilities enhance distribution reliability or resilience and maximize facility participation in wholesale markets.
“We need to keep an eye on our power grid and energy generation; we need to make sure we remain competitive in the markets in years to come,” Sen. Norm Needleman (D), chair of the legislature’s joint Energy and Technology Committee, said in a statement upon passage of the bill.
The nonprofit RENEW Northeast expressed disappointment in passage of the bill at the expense of another storage bill (SB 90), saying in a statement Thursday that HB 5327 would give utilities a “monopoly” for building six energy storage projects.
“The electric distribution companies now have reserved for themselves a large portion of the energy storage market,” said Francis Pullaro, executive director of RENEW. “Insulating the utilities from competition is contrary to Connecticut’s strong, pro-consumer law and unnecessary for any technical reason.”
RENEW urged Lamont to veto the bill.
Connecticut’s energy storage law, which went into effect last year, allows the Department of Energy and Environmental Protection (DEEP) to issue requests for proposals for utility-scale storage projects to reach 300 MW by 2024, 650 MW by 2027 and 1 GW by 2030.
SB 90 would have provided a technical fix so DEEP could move forward with a proceeding launched in October for a competitive storage solicitation under that law. The bill’s language gave DEEP the necessary authority to direct Avangrid and Eversource to enter power purchase agreements for up to 20 years for projects the department selects under the solicitation.
Avangrid and Eversource objected to SB 90 in hearing testimony in February.
“The PPA model only works when the parties can identify a knowable production quantity over which to pay the storage project developer, but there is no such knowable quantity with storage for energy,” Eversource said.
SB 90 was on the Senate calendar at the end of the session, as recommended for passage by the Energy and Technology Committee. No vote was taken on the bill.
Hydrogen Study
The Senate on Tuesday unanimously passed another bill, HB 5200, which would authorize the creation of a task force to study hydrogen-fueled energy opportunities for the state.
Among the task force study parameters are reviews of:
regulations and legislation to achieve economies of scale for hydrogen;
hydrogen-related incentives and programs in the federal Infrastructure Investment and Jobs Act;
workforce development opportunities;
sources of clean hydrogen, including wind, solar, biogas and nuclear; and
funding sources for hydrogen energy programs and infrastructure.
The task force would have to submit a report to the General Assembly by Jan. 15, 2023. The bill now goes to the governor for his signature, having passed the House 142-2 in April.
Ørsted signed a project labor agreement (PLA) Thursday with North America’s Building Trades Unions (NABTU), pledging to fund worker training and use union labor to construct the company’s U.S. offshore wind farms.
Union leaders and Biden administration officials, who joined the company in celebrating the pact at the AFL-CIO Building in Washington, called it proof that clean energy investments can produce economic benefits as well as address climate change.
“This is what we’ve been waiting for,” said Amanda Lefton, director of the Bureau of Ocean Energy Management, who added that it was the first national agreement of its kind. “We’re setting the bar for the rest of the industry.”
The National Offshore Wind Agreement, which was authorized by 15 international union presidents and their local affiliates, covers all Ørsted contractors and subcontractors that will perform offshore windfarm construction in the U.S.
Ørsted operates the nation’s first offshore wind farm, Block Island Wind Farm in Rhode Island, and has six offshore projects in development: Revolution Wind (704 MW) south of Rhode Island and Connecticut; Sunrise Wind (924 MW) and South Fork Wind (132 MW) off New York; Ocean Wind 1 (1,100 MW) and Ocean Wind 2 (1,148 MW) off New Jersey; and Skipjack Wind (966 MW) off Maryland.
Sean McGarvey, president of NABTU, said he was skeptical when AFL-CIO President Elizabeth H. Shuler urged him to seek an agreement for OSW construction.
“I’ll be honest with you. … In the world of onshore wind and solar, our experience for ‘high-road’ construction has not been a good one for the most part,” he said.
He thanked the Biden administration for its “gentle nudging” toward a deal.
“They’ve done more for the poor, the working class and the middle class than anybody in my almost 60 years of life,” he said, comparing the agreement to Franklin Delano Roosevelt’s creation of the Tennessee Valley Authority. “There are hundreds of thousands of families who were born, raised and buried in the middle class through their union cards and working with TVA.”
Ørsted used a PLA in constructing Block Island. Last year, Atlantic Shores Offshore Wind, a joint venture between affiliates of the Anglo/Dutch oil giant Shell and France’s EDF, signed a memorandum of understanding with labor unions for its project off New Jersey. (See Developer to Use Union Labor for NJ OSW Project.)
U.S. Commerce Secretary Gina Raimondo, who helped shepherd Block Island as governor of Rhode Island, said the Block Island PLA resulted in “a really close relationship between labor and business. … It did work. And now we scale that.”
Among the unions signing the agreement are the International Brotherhood of Electrical Workers, the International Union of Operating Engineers, the Laborers’ International Union of North America and the International Association of Bridge, Structural, Ornamental and Reinforcing Iron Workers.
Raimondo made a point to thank “the men and women of the building trades … the folks that get out there every day and do this work.
“That work is dangerous. You know, you try to be an operating engineer going all the way up [a turbine tower] in the middle of the ocean with the wind blowing. This stuff is tough.”
The agreement sets diversity targets and performance monitoring, with workforce equity committees on each project. Ørsted said it has committed $23 million to support new or existing OSW job training programs in the U.S.
“Women, communities of color, formerly incarcerated, there are so many people that are going to be recruited and go through these … training centers up and down the East Coast and learn skill sets to last a lifetime,” McGarvey said.
Public Service Enterprise Group (NYSE:PEG) said Tuesday that it could secure projects costing $1-$3 billion under New Jersey’s solicitation seeking proposals for transmission upgrades.
Speaking during the company’s first quarter earnings call, President and CEO Ralph Izzo said the utility is hopeful that one or more of the proposals it submitted will be picked by the New Jersey Board of Public Utilities (BPU) to help the agency develop a robust transmission system that will tie New Jersey’s offshore wind projects to the grid on land.
PSEG CEO Ralph Izzo | National Clean Energy Week
The initiative is part of PSEG’s sweeping clean energy program now pending as Izzo prepares to step down on Sept. 1, after 30 years at the company and 15 in the top spot. Announcing the retirement in April, PSEG called Izzo a “pioneer” who championed clean energy and the “sustainable business strategy” that helped reduce carbon emissions from the company’s power generation by 98% since 2006.
As part of a planned leadership change, Izzo will continue as executive chair of the board until his retirement on Dec. 31. Current Chief Operating Officer Ralph LaRossa, another 30-year company veteran, will succeed Izzo as president and CEO.
Izzo acknowledged that although the investment in the offshore transmission system “could range” up to $3 billion, it also could be zero. He said the company, which submitted its proposals with Danish offshore wind developer Ørsted, took part in all four public hearings organized by the BPU in the last two months to explore different aspects of the proposed transmission system. The BPU has said it could pick some, all or none of the proposals. (See NJ Seeks Efficiency, Savings in OSW Transmission Process.)
“The solutions we submitted range from single collectors at various landing points to a linked transmission network out in the ocean,” Izzo said.
“We’re not guaranteed anything in that solicitation,” he said, but added that “we happen to think we’re the best bidder in the lot.”
Public Support for Nuclear
Izzo also told investors that the utility plans a $15-$17 billion capital spending program through 2025, the majority of which will support the company’s commitment to cut its carbon emissions in line with the Paris Agreement to limit the global average temperature rise to 1.5 degrees Celsius. The investments are aimed at meeting that goal “either through direct carbon emissions reductions, energy efficiency or climate adaptation,” Izzo said.
“Based on our initial carbon inventory, our Scope 1 and Scope 2 emissions comprised roughly 15% of our total carbon emissions,” Izzo said. “Our challenge, one that we embrace, is to address our largest emissions category, which falls under Scope 3, the largely downstream customer use of our energy products that also includes the emissions profiles of our upstream suppliers.
“We are fully engaged in developing our plans, staffed with technical advisers and internal teams” who are preparing a plan that will go to the UN at the end of the year as part of the organization’s “Race to Zero” initiative, Izzo said. “We are confident that we are creating shareholder value by growing our rate base in alignment with New Jersey’s clean energy goals.”
Scope 1 emissions are those generated by a company’s operations directly under its control, while Scope 2 emissions are those generated by the electricity, steam, heating or cooling a company purchases.
PSEG capital spending 2021-2025E | PSEG
PSEG invested $656 million in the first quarter, part of the expected $2.9 billion in infrastructure spending in 2022 that will be “aligned with NJ’s clean energy goals,” the company said in its presentation.
PSEG in February completed the sale of its fossil plants in New York and Connecticut, and the company last year moved up its pledge to reach net-zero emissions by 2030, rather than the previous goal of 2050.
Nuclear power is expected to play a key role in that strategy. Izzo said he is “hopeful” that a tax incentive to support nuclear plants can be passed in Washington to “preserve the economic viability” of nuclear plants, including those owned by PSEG.
“We have seen a positive shift in public sentiment in support of nuclear power, and its carbon free energy security attributes, since the Russian invasion of Ukraine,” he said. “We do think that current markets might make it easier, candidly, in Washington, to score a production tax credit in terms of the impact on the federal budget. And certainly, that would be helpful in New Jersey to reduce the pressure on New Jersey customers.”
Such credits also would give stability to nuclear plant owners, by providing financial support for years to come, Izzo said. At present, PSEG must apply every three years to the BPU for financial subsidies to support the utility’s three nuclear plants, Hope Creek nuclear power plant and Salem 1 and Salem 2. The BPU, in each of the last two three-year periods, has awarded the plants $300 million under the zero-emission certificate (ZEC) program. (See NJ Nukes Awarded $300 Million in ZECs.)
He said that the Department of Energy (DOE) recently opened a “funding window to help struggling nuclear plants.” The department on April 19 said it was accepting submissions for the $6 billion Civil Nuclear Credit Program. (See DOE Launches $6B Nuke Credit Program.)
But none of PSEG’s nuclear plants meet the criteria for funding, Izzo said. The first cycle of awards from the program will “prioritize reactors that have already announced their intention to cease operations,” according to the DOE.
“We will endeavor to obtain the maximum benefit for our nuclear units from the DOE program, should we qualify in future rounds,” he said. “However, we do not believe that the DOE grant program provides sufficient revenue stability or visibility needed to make longer-dated fuel and license extension decisions.”
Earnings
PSEG reported a net loss of $2 million, (-$0.01/share), for the first quarter compared to net income of $648 million, or $1.28 per share, in the first quarter of 2021, according to its earnings release. Non-GAAP operating earnings for the first quarter were $672 million, or $1.33 per share, compared to non-GAAP operating earnings of $650 million, or $1.28 per share, in the first quarter of 2021.
The net loss in GAAP reported earnings reflected $674 million of reconciling items, mainly mark-to-market adjustments “related to higher energy prices versus our existing forward-sale contracts,” Izzo said.
The results show “solid utility and nuclear operations and rate base growth from regulated investments, as well as lower cost resulting from the completed sale of PSEG Fossil that will benefit first-half 2022 comparisons,” he said.
Pacific Gas and Electric (NYSE:PCG) announced an ambitious pilot project to test the feasibility of transporting “zero-carbon” hydrogen in natural gas pipelines and burning the fuel for electric generation.
The utility said Monday it will launch the nation’s “most comprehensive end-to-end hydrogen study and demonstration facility” in partnership with Northern California Power Agency (NCPA), Siemens Energy, the City of Lodi, Calif., University of California, Riverside, and GHD Inc., an Australia-based engineering and construction consulting firm with experience in hydrogen projects.
The “centerpiece” of the “Hydrogen to Infinity” study will be a large-scale project to blend hydrogen and natural gas in a standalone pipeline system near NCPA’s Lodi Energy Center (LEC), a 300-MW combined-cycle gas-fired generator in Lodi, Calif.
“This demonstration facility is truly an exciting advancement of our goal to diversify our natural gas system for our customers and consider hydrogen’s role as part of California’s decarbonized future,” PG&E Gas Engineering Senior Vice President Janisse Quiñones said in a press release.
PG&E expects to break ground on the project in 2023, utility spokesperson Melissa Subbotin told NetZero Insider.
Located on 130 acres, the facility “will allow for a controlled and safe study of hydrogen injection, storage and combustion of different hydrogen blends in a variety of end uses,” according to PG&E. The plant will accept the hydrogen-gas blend for electric generation in a Siemens 5000F4 gas turbine.
Lodi is about 85 miles northeast of PG&E’s headquarters in San Francisco, but PG&E’s decision to pair with the LEC appears to have been based on more than just geography. In 2020, NCPA initiated a two-phase project to equip the LEC with technology capable of burning a natural gas blend containing up to 45% hydrogen. Phase 1 of the effort included the installation of a new turbine, while Phase 2, expected to be completed next year, will entail installing hydrogen-capable combustors within the turbine.
Subbotin said most of the project’s hydrogen will be produced on the Lodi site. And while some of the hydrogen used will be produced by electrolysis, the project will explore “other production methods,” she said.
“The initial scope of the project doesn’t include testing the feasibility of 100% hydrogen in the pipelines and turbines. However, this may be considered in future phases depending on the initial findings and results,” Subbotin said.
According to PG&E’s release, the pilot will focus on the technical, operational and safety needs of working with hydrogen, as well as developing a market for the fuel. The new Lodi facility will also serve as a “functional test environment” for ongoing research and a training environment for new technology, the utility said.
”Feasibility studies of hydrogen are an essential part of our growth and evolution as a natural gas utility,” Quiñones said, citing PG&E’s commitment to reduce greenhouse gas emissions. “This new facility will provide critical research, close information gaps and unlock opportunities not only for PG&E, but for the entire global network of natural gas pipeline operators.”
PG&E is also “contemplating” making the facility a focal point for a potential Northern California hydrogen hub.
Asked whether PG&E would vie for a piece of the $8 billion in funding the U.S. Department of Energy is making available to support development of at least four hydrogen hubs nationwide, Subbotin said the utility “is considering any funding opportunities where the scope of work at this demonstration facility meets the solicitation criteria.
“The specifics and qualifications for DOE hydrogen hubs are still unknown,” she added.
Expansion of the U.S. transmission grid to accommodate decarbonization will require more humility from developers and active support by states, speakers on an Advanced Energy Economy webinar said Tuesday.
The webinar, titled “Making connections: How to get transmission built,” began with a keynote by FERC Chair Richard Glick, who outlined the Notice of Proposed Rulemaking the commission issued April 21 that would require RTOs and ISOs to incorporate scenarios and probabilistic concepts to develop transmission plans looking 20 years into the future. (See FERC Issues 1st Proposal out of Transmission Proceeding.)
Glick noted that the NOPR also would require transmission planners to seek state approval for cost allocation of regional grid projects.
Sarah Webster, Pattern Energy | Pattern Energy
“The states are going to be resistant [to transmission expansion if they think] we’re being unfair and we’re shoving cost on one state versus another state,” he said. “Siting [is] a big example. But states have other abilities as well to prevent their utilities from further developing what in many cases most people would believe is much-needed transmission.”
Glick also highlighted FERC’s Joint Federal-State Task Force on Electric Transmission, which will hold its third meeting on Friday.
“It is absolutely critical that the states … meet the feds halfway to understand what transmission can mean — what grid reliability and deployment of renewables and decarbonization — can mean for the ratepayers and for their voters,” said Sarah Webster, senior vice president of external affairs and market development for Pattern Energy.
A Win in the Southwest
In December, Pattern completed construction of Western Spirit Wind, the largest renewable energy project in the U.S., with four wind farms totaling more than 1,050 MW in central New Mexico.
Pattern built the project to take advantage of New Mexico’s winds, which blow strongest in the morning and night, to complement California’s surfeit of solar power, Webster said. The project’s 377 General Electric wind turbines were accompanied by a 155-mile, 345-kV transmission line that connects with the Public Service Company of New Mexico system near Albuquerque.
“If you want to run a grid on technologies that are reliant on the weather, that’s fine; you can do it in a cost-effective and fully reliable way. But you need a grid that’s bigger than the weather,” she said. “You need the hydro coming in from the Pacific Northwest; you need the wind coming in from the Eastern states; you need the solar that you see in Nevada and California. When you put those all together with some storage and some natural gas for firming and shaping, you’ve got a really reliable baseload-type product energy product.”
But building transmission, she said, “takes patient money” and “a deep engagement with many, many regulatory bodies” and stakeholders.
“The very big reality is, whether we’re doing a 100-mile [transmission] line or a 500-mile [transmission] line, pretty much anyone can stop it. You can have local jurisdiction, county jurisdiction, state jurisdiction. And you don’t typically have condemnation rights.”
Overcoming landowner opposition “takes a lot of engagement. It takes a lot of humility. You’ve got to talk to people from where they’re at. You can’t come in political. You can’t come in with preconceived ideas. You can’t come in even with the implicit idea that this is essential for the greater good. You have to come in, when you’re talking with landowners, profoundly respectful, that you may be dealing with heritage ranches that have been in families for over a century. And you need to be willing to sit down, listen, have hard conversations [and] follow up again.
“And then you have to work with their concerns. … They can say, ‘You know, I am protective of this particular view. Can you work on the routing around this precious part of the land for me?’ And so I think that that’s really the key to engagement.”
Webster said Pattern takes a broad view of its “host community.”
“You’re a host community if you’re hosting an actual facility with turbines or panels. You’re a host community if you’re hosting a substation, or a major piece of transmission infrastructure. But to us, you’re also a host community if you’re supporting the public good by allowing your transmission line to pass through your county or your property. And so we created standardized community benefits packages based on just mileage that [is] consistent across our entire footprint.”
‘Purple Strategy’
One of the keys to the success of Western Spirit’s transmission line, Webster said, was Pattern’s “partnership” with the New Mexico Renewable Energy Transmission Authority (RETA), which does have eminent domain rights. Over the 155-mile route, Webster said Pattern used condemnation “on four parcels in a very non-contested way.”
Webster said other states have taken note of New Mexico’s approach, with Colorado lawmakers recently creating the Colorado Energy Transmission Authority and California considering similar legislation.
“This is not a Democrat thing or Republican thing. I mean, most people don’t realize that 86% of all wind farms in the United States of America are operating in Republican districts,” she said. “This is a purple strategy. Maybe in some states, it’s a renewable energy authority; maybe in others, it’s an infrastructure authority. But it basically empowers the state and its agencies to make some decisions in support of … decarbonization, economics for citizens and economic development.”
Challenges in the Northeast
Macky McCleary, Guidehouse | Guidehouse
Another panelist, Macky McCleary, director of energy, sustainability and infrastructure for Guidehouse, discussed the difficulty of siting infrastructure in the Northeast.
“The challenge in highly congested areas like the Northeast is that there’s just no space. And these projects require space, even in states like Massachusetts, which have very lofty, renewable goals,” he said. “They spent 20 years trying to build Cape Wind, which isn’t even on land. They said no to it because they could see it from land in the ocean. To me, that is a great example of how challenged we are going to be. Really the challenge for this is not money; it’s not going to be regulatory. It’s not going to be legal. It’s not going to be capital. It’s going to be political.”
McCleary said FERC’s NOPR is “a potentially really big deal.”
And he said he was cheered that two transmission projects in the Northeast — the Champlain Hudson Power Express, which would deliver 1,250 MW of hydropower to New York City, and the New England Clean Power Link, which would deliver 1,000 MW of power from the Canadian border to Vermont and ISO-NE — will be built.
McCleary said the failure of the Northern Pass project, which would have brough 1,090 MW of Canadian hydropower into New England, helped the Vermont project because of the state’s “culture around renewable energy and the environment.”
The New York project benefited from the “sort of emperor governorship [that] allows them to be able to do some things that other states would not be able to do from a stakeholder point of view … [the] ability to sort of move heaven and earth, because the governor says so.”
Although siting offshore wind is easier than siting land-based projects, McCleary said he is concerned about how the transmission will be designed to deliver their power.
“If we contract out transmission for each individual parcel, we’re going to end up overbuilding transmission for the needs of the entire system. The challenge is that you’re running through several different RTOs here, and it’s not clear whose job it is to ensure that this is done in an efficient way,” he said.
He said he was encouraged by the New York Public Service Commission’s recent order requiring future OSW projects be “mesh ready,” with capacity to connect to a future offshore grid. (See New York Seeks to Protect Tx Options with Mesh-ready OSW.)
“I think it’s necessary for all of the different regulatory bodies to look into this going forward, or we’re going to end up overpaying for this resource that is so abundant off the Atlantic Seaboard.”
Sensors and Markets
Also appearing on the panel was Mona Tierney-Lloyd, head of U.S. and state public policy for Enel North America, who discussed how drought, wildfires and resource adequacy concerns are leading many to consider a potential RTO in the West. (See Western Utilities to Support SPP Market Development.)
An RTO would allow “the coordination of operation across a Western footprint, being able to plan transmission development on a regional basis and the cost allocation of those assets [and to eliminate] pancaked rates, which make it very expensive to move electricity generated in the West from point to point.”
Hilary Pearson, senior director of governmental and regulatory affairs for LineVision, which makes sensors for monitoring transmission line conditions.
Pearson noted the growing use of sensors in medicine, personal fitness and cars. “We’re really excited at the opportunity to help bring some of that data-driven efficiency and visibility [and] consumer benefits to the electric grid.”
The Western Energy Imbalance Market (WEIM) took on the Bonneville Power Administration and Tucson Electric Power (TEP) (NYSE:FTS) as new participants on Tuesday, marking the market’s largest single expansion since it began operating in November 2014 with PacifiCorp as its first member.
BPA’s journey into the WEIM has been an especially complicated one. The federal power marketing administration first announced its interest in joining the market in 2018. What followed was three years of stakeholder meetings to make a final determination on membership, at times held in parallel with workshops to help prepare the agency’s customers for implementation.
The agency was originally scheduled to begin trading in the WEIM in early April, along with Pacific Northwest utilities Avista and Tacoma Power. But in January, BPA officials postponed entry to address technology and customer training issues, giving the final go-ahead for the May 3 entry only two weeks ago after determining those problems had been sufficiently addressed. (See BPA Set to Go Live in Western EIM in May.)
“Joining the Western EIM is a monumental and meaningful step in the modernization of our operations that unlocks a range of benefits for Bonneville and our customers,” BPA Administrator John Hairston said in a statement. “As we explore additional market-based opportunities to maximize the value of our surplus power and the Northwest’s federal transmission system, we will ensure that they are consistent with our statutory authority and further our ability to deliver affordable, reliable energy to our customers.”
BPA brings a massive amount of transmission into the WEIM. The agency’s 15,000 miles of lines comprise about 75% of the network in the Northwest, and its partial ownership of the California-Oregon Intertie and the Pacific DC Intertie will greatly increase the WEIM’s transfer capability between the Pacific Northwest and California.
BPA also controls 31 hydroelectric projects in the Federal Columbia River Power System (FCRPS), rated at a combined 22.5 GW. Its balancing authority area additionally interconnects generation from other numerous other producers, including over 2.9 GW of nameplate wind capacity.
Hydro accounts for about 80% of the generation capacity in BPA’s BAA, followed by wind (10.2%), nuclear (4.3%), gas (3.9%) and geothermal (1.4%). In the WEIM, the Northwest’s hydro output is expected to serve as a fast-ramping, firming complement to California’s rapidly growing — and variable — solar capacity. On the flip side, load-serving entities in the north should be better positioned to absorb CAISO’s mid-day solar surpluses.
‘Vital Source’
The entry of TEP further extends the WEIM’s reach into Arizona, with Arizona Public Service and Salt River Project already participating.
TEP owns or controls about 2,500 MW of generating capacity, including 298 MW of utility-scale solar and 429 MW of wind. Its service area contains about 301 MW of commercial and residential rooftop solar.
“We’re working toward a dramatic expansion of renewable resources, and participating in the WEIM provides another way to increase our use of wind and solar energy,” TEP CEO Susan Gray said.
The utility also operates 2,175 miles of high-voltage transmission, with key links into wind-rich New Mexico and the neighboring BAA of Public Service Company of New Mexico, which joined the market last year.
CAISO CEO Elliot Mainzer lauded BPA and TEP staff for their efforts in preparing to join the WEIM.
“I am very appreciative of the hard work and focus required to meet this important milestone and look forward to delivering real economic and environmental value to BPA and TEP customers, Mainzer said in a statement posted on LinkedIn.
In a separate statement, Mainzer, who formerly headed BPA, noted that the FCRPS “is a vital source of clean energy that will bring significant resource diversity and transmission capability to the WEIM.” He also called TEP “another highly valued partner in the Desert Southwest.”
With the entry of the BPA and TEP, the WEIM now includes 19 members accounting for 77% of the load in the Western Interconnection.
In the first quarter of this year, the market topped $2 billion in total benefits for its participants, reaching that mark 20 months after hitting $1 billion in benefits. (See Western EIM Tops $2B in Benefits.) The accumulation of benefits is expected to accelerate with the admission of BPA into the market.
Panelists at a meeting hosted in Albany, N.Y., on Tuesday by the conservative think tank Empire Center for Public Policy questioned the pace and cost of the state’s statutory plan to move away from natural gas and electrify most home heating and transportation by 2050.
If New York’s Climate Leadership and Community Protection Act (CLCPA) is anything like other state-sponsored projects, it could cost more than $500 billion, but its benefits could total around only $200 billion by midcentury, James Hanley, senior policy analyst at the Empire Center, said in introducing a new report on perceived risks in the state’s climate action plan.
The CLCPA targets 70% of the state’s electricity to come from renewable resources by 2030 and greenhouse gas emissions to be cut 85% from 1990 levels by midcentury. The law also created a Climate Action Council, which by year-end will finalize its draft scoping plan to be submitted to state lawmakers for implementation.
The All-Electric Building Act (S6843A), now in the state Senate Finance Committee, would alter the state’s Energy Conservation Construction Code to prohibit fossil fuel infrastructure and equipment in new building construction statewide no later than Dec. 31, 2023, if the building is less than seven stories, and by July 1, 2027, for all buildings.
The meeting featured representatives from business groups, state regulatory agencies, generators and utilities.
National Grid (NYSE:NGG), which operates several electric and gas utilities upstate and in New York City and Long Island, earlier this year won a state offshore wind solicitation and last month launched its own initiative to counter the state’s climate action plan.
“We can get to the same end state in a more cost-effective, pragmatic, reliable way with a high probability of success,” said Donald Chahbazpour, National Grid’s director of policy and regulatory strategy for the future of heat.
The CLCPA requires a significant buildup of the electric system, which National Grid’s clean energy plan has quantified to about 60 GW or about $70 billion in capital investments, which then translates to $1,000/year for heating customers, Chahbazpour said.
“To give you a sense of that fuller buildout … today the gas network delivers three to four times more energy on its peak day than the electric system delivers on its peak day, so if you begin to shift heating from natural gas to electricity, you may need to triple or quadruple the electric system,” he said.
There are real local pollution issues with fossil generation, particularly in downstate New York, but upstate residents are generally unaware that they will be paying 60% of the costs to clean up the air in Queens, New York Public Service Commissioner John Howard said.
“The clean energy transition is basically the recapitalization of our entire energy system. … Nobody’s ever done that, not even come close,” Howard said.
No matter what the urgency of the existential threat of climate change, reliability still comes first, he said.
“The energy capital, Houston, could tolerate 10 to 12 hours of power outage, but the real capital of the country, New York, will not — that’s not going to happen in Times Square,” Howard said.
While there is no funding mechanism in the climate law, state agencies run myriad clean energy-related programs, but it’s hard to evaluate how effective they are collectively, said Gavin Donohue, president and CEO of the Independent Power Producers of New York (IPPNY) and a member of the Climate Action Council.
“The state needs to start walking the walk as well. … Will the new Buffalo Bills stadium operate on natural gas? Is the $7 billion Penn Station renovation project compliant with the CLCPA?” Donohue said.
Business owners and managers have a hard time understanding the financial and regulatory implications behind a complicated law like the CLCPA, said Ken Pokalsky, vice president of the Business Council of New York State (BCNYS), which represents about 3,500 companies across all sectors.
“We really need to be very mindful of adopting measures that result in emissions and economic leakage from the state,” Pokalsky said. “We know that is a real phenomenon and that’s our No. 1 concern.”
Consumer costs from the environmental legislation in New York are going to be “exorbitant,” a spike that comes after the state has been leading the country by reducing emissions by 95% from 1990 to 2020, said Michael Butler, mid-Atlantic regional director for the Consumer Energy Alliance.
“I wish I had some better news, but it just looks like you’re on a path for just open costs, and those costs also are going to lead to a job flow out of the state of New York. As a Pennsylvania person, I will benefit a little bit, but I feel bad for you guys,” Butler said.
